Ten Year Site Plan:

: 2016-2025 City of Tallahassee Utilities Photo: Purdom Unit 8 Report prepared by: City of Tallahassee Electric System Integrated Planning

CITY OF TALLAHASSEE TEN YEAR SITE PLAN FOR ELECTRICAL GENERATING FACILITIES AND ASSOCIATED TRANSMISSION LINES 2016-2025 TABLE OF CONTENTS I. Description of Existing Facilities 1.0 Introduction... 1 1.1 System Capability... 1 1.2 Purchased Power Agreements... 2 Figure A Service Territory Map... 3 Table 1.1 FPSC Schedule 1 Existing Generating Facilities... 4 II. Forecast of Energy/Demand Requirements and Fuel Utilization 2.0 Introduction... 5 2.1 System Demand and Energy Requirements... 5 2.1.1 System Load and Energy Forecasts... 5 2.1.2 Load Forecast Uncertainty & Sensitivities... 8 2.1.3 Energy Efficiency and Demand Side Management Programs... 9 2.2 Energy Sources and Fuel Requirements... 12 Table 2.1 FPSC Schedule 2.1 History/Forecast of Energy Consumption (Residential and Commercial Classes)... 13 Table 2.2 FPSC Schedule 2.2 History/Forecast of Energy Consumption (Industrial and Street Light Classes)... 14 Table 2.3 FPSC Schedule 2.3 History/Forecast of Energy Consumption (Utility Use and Net Energy for Load)... 15 Figure B1 Energy Consumption by Customer Class (2006-2025)... 16 Figure B2 Energy Consumption: Comparison by Customer Class (2016 and 2025)... 17 Table 2.4 FPSC Schedule 3.1.1 History/Forecast of Summer Peak Demand Base Forecast... 18 Table 2.5 FPSC Schedule 3.1.2 History/Forecast of Summer Peak Demand High Forecast... 19 Table 2.6 FPSC Schedule 3.1.3 History/Forecast of Summer Peak Demand Low Forecast... 20 Table 2.7 FPSC Schedule 3.2.1 History/Forecast of Winter Peak Demand Base Forecast... 21 Table 2.8 FPSC Schedule 3.2.2 History/Forecast of Winter Peak Demand High Forecast... 22 Table 2.9 FPSC Schedule 3.2.3 History/Forecast of Winter Peak Demand Low Forecast... 23 Table 2.10 FPSC Schedule 3.3.1 History/Forecast of Annual Net Energy for Load Base Forecast... 24 Table 2.11 FPSC Schedule 3.3.2 History/Forecast of Annual Net Energy for Load High Forecast... 25 Table 2.12 FPSC Schedule 3.3.3 History/Forecast of Annual Net Energy for Load Low Forecast... 26 Table 2.13 FPSC Schedule 4 Previous Year Actual and Two Year Forecast Demand/Energy by Month... 27 Table 2.14 Load Forecast: Key Explanatory Variables... 28 Table 2.15 Load Forecast: Sources of Forecast Model Input Information... 29 Figure B3 Banded Summer Peak Load Forecast vs. Supply Resources... 30 Table 2.16 Projected DSM Energy Reductions... 31 Table 2.17 Projected DSM Seasonal Demand Reductions... 32 Table 2.18 FPSC Schedule 5.0 Fuel Requirements... 33 Table 2.19 FPSC Schedule 6.1 Energy Sources (GWh)... 34 Table 2.20 FPSC Schedule 6.2 Energy Sources (%)... 35 Figure B4 Generation by Fuel Type (2016 and 2025)... 36

III. Projected Facility Requirements 3.1 Planning Process... 37 3.2 Projected Resource Requirements... 37 3.2.1 Transmission Limitations... 37 3.2.2 Reserve Requirements... 38 3.2.3 Recent and Near Term Resource Changes... 38 3.2.4 Power Supply Diversity... 39 3.2.5 Renewable Resources... 41 3.2.6 Future Power Supply Resources... 42 Figure C System Peak Demands and Summer Reserve Margins... 45 Table 3.1 FPSC Schedule 7.1 Forecast of Capacity, Demand and Scheduled Maintenance at Time of Summer Peak... 46 Table 3.2 FPSC Schedule 7.2 Forecast of Capacity, Demand and Scheduled Maintenance at Time of Winter Peak... 47 Table 3.3 FPSC Schedule 8 Planned and Prospective Generating Facility Additions and Changes... 48 Table 3.4 Generation Expansion Plan... 49 IV. Proposed Plant Sites and Transmission Lines 4.1 Proposed Plant Site... 51 4.2 Transmission Line Additions/Upgrades... 51 Table 4.1 FPSC Schedule 9 Status Report and Specifications of Proposed Generating Facilities... 53 Figure D1 Hopkins Plant Site... 54 Figure D2 Purdom Plant Site... 54 Table 4.2 Planned Transmission Projects 2016-2025... 55 Table 4.3 FPSC Schedule 10 Status Report and Spec. of Proposed Directly Associated Transmission Lines... 56

Chapter I Description of Existing Facilities 1.0 INTRODUCTION The City of Tallahassee ( City ) owns, operates, and maintains an electric generation, transmission, and distribution system that supplies electric power in and around the corporate limits of the City. The City was incorporated in 1825 and has operated since 1919 under the same charter. The City began generating its power requirements in 1902 and the City's Electric Utility presently serves approximately 117,825 customers located within a 221 square mile service territory (see Figure A). The Electric Utility operates three generating stations with a total summer season net generating capacity of 746 megawatts (MW). The City has two fossil-fueled generating stations, which contain combined cycle (CC), steam and combustion turbine (CT) electric generating facilities. The Sam O. Purdom Generating Station, located in the City of St. Marks, Florida has been in operation since 1952; and the Arvah B. Hopkins Generating Station, located on Geddie Road west of the City, has been in commercial operation since 1970. The City has also been generating electricity at the C.H. Corn Hydroelectric Station, located on Lake Talquin west of Tallahassee, since August of 1985. 1.1 SYSTEM CAPABILITY The City maintains seven points of interconnection with Duke Energy Florida ( Duke, formerly Progress Energy Florida); three at 69 kv, three at 115 kv, and one at 230 kv; and a 230 kv interconnection with Georgia Power Company (a subsidiary of the Southern Company ( Southern )). As shown in Table 1.1 (Schedule 1), 222 MW (net summer rating) of CC generation and 20 MW (net summer rating) of CT generation facilities are located at the City's Sam O. Purdom Generating Station. The Arvah B. Hopkins Generating Station includes 300 MW (net summer rating) of CC generation, 76 MW (net summer rating) of steam generation and 128 MW (net summer rating) of CT generation facilities. Page 1

The City's Hopkins 1 steam generating unit can be fired with natural gas. The CC and CT units can be fired on either natural gas or diesel oil but cannot burn these fuels concurrently. The total capacity of the three units at the C.H. Corn Hydroelectric Station is 11 MW. However, because the hydroelectric generating units are effectively run-of-river (dependent upon rainfall, reservoir and downstream conditions), the City considers these units as energy only and not as dependable capacity for planning purposes. The City s current total net summer installed generating capability is 746 MW. The corresponding winter net peak installed generating capability is 822 MW. Table 1.1 contains the details of the individual generating units. 1.2 PURCHASED POWER AGREEMENTS The City has no long-term firm capacity and energy purchase agreements. Firm retail electric service is purchased from and provided by the Talquin Electric Cooperative ( Talquin ) to City customers served by the Talquin electric system. The projected amounts of electric service to be purchased from Talquin is included in the Annual Firm Interchange values provided in Table 2.19 (Schedule 6.1). In accordance with their agreement certain Talquin facilties within the geographic boundaries of the City electric system service territory will be transferred to the City over the coming years. It is anticipated that these transfers will be completed by 2019 at which time all City customers will be served via City facilities. Reciprocal service is provided to Talquin customers served by the City electric system. Payments for electric service provided to and received from Talquin and the transfer of customers and electric facilities is governed by a territorial agreement between the City and Talquin. Page 2

Figure A City of Tallahassee, Electric Utility Service Territory Map ) "" ~ r:,,111 ~'O~5LG_~_A. - '. Page 3

Table 1.1 City Of Tallahassee Schedule 1 Existing Generating Facilities As of December 31, 2015 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) Alt. Fuel Commercial Expected Gen. Max. Net Capability Unit Unit Fuel Fuel Transport Days In-Service Retirement Nameplate Summer Winter Plant No. Location Type Primary Alternate Primary Alternate Use Month/Year Month/Year (kw) (MW) (MW) S. O. Purdom 8 Wakulla CC NG FO2 PL TK [1, 2] 7/00 12/40 270,100 222 258 [7] GT-1 GT NG FO2 PL TK [1, 2] 12/63 10/17 15,000 10 10 GT-2 GT NG FO2 PL TK [1, 2] 5/64 10/17 15,000 10 10 Plant Total 242 278 A. B. Hopkins 1 Leon ST NG NA PL NA [3] 5/71 1/21 75,000 76 78 2 CC NG FO2 PL TK [2] 6/08 [4] Unknown 358,200 [5] 300 330 [7] GT-1 GT NG FO2 PL TK [2] 2/70 4/17 16,320 12 14 GT-2 GT NG FO2 PL TK [2] 9/72 4/18 27,000 24 26 GT-3 GT NG FO2 PL TK [2] 9/05 Unknown 60,500 46 48 GT-4 GT NG FO2 PL TK [2] 11/05 Unknown 60,500 46 48 Plant Total 504 544 C. H. Corn 1 Leon HY WAT NA WAT NA NA 9/85 Unknown 4,440 0 0 Hydro Station 2 HY WAT NA WAT NA NA 8/85 Unknown 4,440 0 0 [6] 3 HY WAT NA WAT NA NA 1/86 Unknown 3,430 0 0 Plant Total 0 0 Total System Capacity as of December 31, 2015 746 822 Notes [1] Due to the Purdom facility-wide emissions caps, utilization of liquid fuel at this facility is limited. [2] The City maintains a minimum distillate fuel oil storage capacity sufficient to operate the Purdom plant approximately 9 days and the Hopkins plant and approximately 3 days at maximum output. [3] Hopkins 1 is a "gas only" unit. [4] Reflects the commercial operations date of Hopkins 2 repowered to a combined cycle generating unit with a new General Electric Frame 7A combustion turbine. The original commercial operations date of the existing steam turbine generator was October 1977. [5] Hopkins 2 nameplate rating is based on combustion turbine generator (CTG) nameplate and modeled steam turbine generator (STG) output in a 1x1 combined cycle (CC) configuration with supplemental duct firing. [6] Because the C. H. Corn hydroelectric generating units are effectively run-of-river (dependent upon rainfall, reservoir and downstream conditions), the City considers these units as "energy only" and not as dependable capacity for planning purposes. [7] Summer and winter ratings are based on 95 o F and 29 o F ambient temperature, respectively. Page 4

CHAPTER II Forecast of Energy/Demand Requirements and Fuel Utilization 2.0 INTRODUCTION Chapter II includes the City s forecasts of demand and energy requirements, energy sources and fuel requirements. This chapter also explains the impacts attributable to the City s current Demand Side Management (DSM) plan. The City is not subject to the requirements of the Florida Energy Efficiency and Conservation Act (FEECA) and, therefore, the Florida Public Service Commission (FPSC) does not set numeric conservation goals for the City. However, the City expects to continue its commitment to the DSM programs that prove beneficial to the City s ratepayers. 2.1 SYSTEM DEMAND AND ENERGY REQUIREMENTS Historical and forecast energy consumption and customer information are presented in Tables 2.1, 2.2 and 2.3 (Schedules 2.1, 2.2, and 2.3). Figure B1 shows the historical total energy sales and forecast energy sales by customer class. Figure B2 shows the percentage of energy sales by customer class (excluding the impacts of DSM) for the base year of 2016 and the horizon year of 2025. Tables 2.4 through 2.12 (Schedules 3.1.1-3.3.3) contain historical and base, high, and low forecasts of seasonal peak demands and net energy for load. Table 2.13 (Schedule 4) compares actual and two-year forecast peak demand and energy values by month for the 2015-2017 period. 2.1.1 SYSTEM LOAD AND ENERGY FORECASTS The peak demand and energy forecasts contained in this plan are the results of the load and energy forecasting study performed by the City. The forecast is developed utilizing a methodology that the City first employed in 1980, and has since been updated and revised every one or two years. The methodology consists of nine multi-variable linear regression models and four models that utilize subjective escalation assumptions and known incremental additions. All Page 5

models are based on detailed examination of the system's historical growth, usage patterns and population statistics. Several key regression formulas utilize econometric variables. Table 2.14 lists the econometric-based linear regression forecasting models that are used as predictors. Note that the City uses regression models with the capability of separately predicting commercial customers and consumption by rate sub-class: general service nondemand (GS), general service demand (GSD), and general service large demand (GSLD). These, along with the residential class, represent the major classes of the City's electric customers. In addition to these customer class models, the City s forecasting methodology also incorporates into the demand and energy projections estimated reductions from interruptible and curtailable customers. The key explanatory variables used in each of the models are indicated by an X on the table. Table 2.15 documents the City s internal and external sources for historical and forecast economic, weather and demographic data. These tables summarize the details of the models used to generate the system customer, consumption and seasonal peak load forecasts. In addition to those explanatory variables listed, a component is also included in the models that reflect the acquisition of certain Talquin Electric Cooperative (Talquin) customers over the study period consistent with the territorial agreement negotiated between the City and Talquin and approved by the FPSC. The customer models are used to predict the number of customers by customer class, some of which in turn serve as input into their respective customer class consumption models. The customer class consumption models are aggregated to form a total base system sales forecast. The effects of DSM programs and system losses are incorporated in this base forecast to produce the system net energy for load (NEL) requirements. Since 1992, the City has used two econometric models to separately predict summer and winter peak demand. Table 2.14 also shows the key explanatory variables used in the demand models. The seasonal peak demand forecasts are developed first by forecasting expected system load factor. Based on the historical relationship of seasonal peaks to annual NEL, system load factors are projected separately relative to both summer and winter peak demand. The predictive variables for projected load factors versus summer peak demand include maximum summer temperature, maximum temperature on the day prior to the peak and real residential price of electricity. For projected load factors versus winter peak demand minimum winter temperature, Page 6

degree-days heating the day prior to the winter peak day, deviation from a base minimum temperature of 22 degrees and annual degree-days cooling are used as input. The projected load factors are then applied to the forecast of NEL to obtain the summer and winter peak demand forecasts. Some of the most significant input assumptions for the forecast are the incremental load modifications at Florida State University (FSU), Florida A&M University (FAMU), Tallahassee Memorial Hospital (TMH) and the State Capitol Center. These four customers represented approximately 17% of the City s 2015 energy sales. Their incremental additions are highly dependent upon annual economic and budget constraints, which would cause fluctuations in their demand projections if they were projected using a model. Therefore, each entity submits their proposed incremental additions/reductions to the City and these modifications are included as submitted in the load and energy forecast. The rate of growth in residential and commercial customers is driven by the projected growth in Leon County population. While population growth projections decreased in the years immediately following the 2008-2009 recession the current projection shows a slightly higher growth in population versus last year. Leon County population is projected to grow from 2016-2035 at an average annual growth rate (AAGR) of 0.83%. This growth rate is below that for the state of Florida (1.20%) but is higher than that for the United States (0.71%). Total and per customer demand and energy requirements have also decreased in recent years. There are several reasons for this decrease including but not limited to the issuance of new or updated federal appliance and equipment efficiency standards since 2009 and the 2010 modifications to the State of Florida Energy Efficiency Code for Building Construction. The City s energy efficiency and demand-side management (DSM) programs (discussed in Section 2.1.3) and the economic conditions during and following the 2008-2009 recession have also contributed to these decreases. The decreases in per customer residential and commercial demand and energy requirements are projected to somewhat offset the increased growth rate in residential and commercial customers. Therefore, it is not expected that base demand and energy growth will return to pre-recession levels in the near future. The City believes that the routine update of forecast model inputs, coefficients and other minor model refinements continue to improve the accuracy of its forecast so that they are more consistent with the historical trend of growth in seasonal peak demand and energy consumption. Page 7

The changes made to the forecast models for load and energy requirements have resulted in 2016 base forecasts for summer peak demand and annual sales/net energy for load that are generally comparable to the corresponding 2015 base forecasts. The winter peak demand forecast has been increased so that the projection is more consistent with the historical trend of actual winter peak demands. 2.1.2 LOAD FORECAST UNCERTAINTY & SENSITIVITIES To provide a sound basis for planning, forecasts are derived from projections of the driving variables obtained from reputable sources. However, there is significant uncertainty in the future level of such variables. To the extent that economic, demographic, weather, or other conditions occur that are different from those assumed or provided, the actual load can be expected to vary from the forecast. For various purposes, it is important to understand the amount by which the forecast can be in error and the sources of error. To capture this uncertainty, the City produces high and low range results that address potential variance in driving population and economic variables from the values assumed in the base case. The base case forecast relies on a set of assumptions about future population and economic activity in Leon County. However, such projections are unlikely to exactly match actual experience. Population and economic uncertainty tends to result in a deviation from the trend over the long term. Accordingly, separate high and low forecast results were developed to address population and economic uncertainty. These ranges are intended to capture approximately 80% of occurrences (i.e., +/- 1.3 standard deviations). The high and low forecasts shown in this year s report use statistics provided by Woods & Poole Economics, Inc. (Woods & Poole) to develop a range of potential outcomes. Woods & Poole publishes several statistics that define the average amount by which various projections they have provided in the past are different from actual results. The City s load forecasting consultant, Leidos Engineering, interpreted these statistics to develop ranges of the trends of economic activity and population representing approximately 80% of potential outcomes. These statistics were then applied to the base case to develop the high and low load forecasts presented in Tables 2.5, 2.6, 2.8, 2.9, 2.11 and 2.12 (Schedules 3.1.2, 3.1.3, 3.2.2, 3.2.3, 3.3.2 and 3.3.3). Page 8

Sensitivities on the peak demand forecasts are useful in planning for future power supply resource needs. The graph shown in Figure B3 compares summer peak demand (multiplied by 117% for reserve margin requirements) for the three forecast sensitivity cases with reductions from proposed DSM portfolio and the base forecast without proposed DSM reductions against the City s existing and planned power supply resources. This graph allows for the review of the effect of load growth and DSM performance variations on the timing of new resource additions. The highest probability weighting, of course, is placed on the base case assumptions, and the low and high cases are given a smaller likelihood of occurrence. 2.1.3 ENERGY EFFICIENCY AND DEMAND SIDE MANAGEMENT PROGRAMS The City currently offers a variety of conservation and DSM measures to its residential and commercial customers, which are listed below: Residential Measures Energy Efficiency Loans Gas New Construction Rebates Gas Appliance Conversion Rebates Information and Energy Audits Ceiling Insulation Grants Low Income Ceiling Insulation Grants Low Income HVAC/Water Heater Repair Grants Neighborhood REACH Weatherization Assistance Energy Star Appliance Rebates High Efficiency HVAC Rebates Energy Star New Home Rebates Solar Water Heater Rebates Solar PV Net Metering Duct Leak Repair Grants Variable Speed Pool Pump Rebates Nights & Weekends Pricing Plan Commercial Measures Energy Efficiency Loans Demonstrations Information and Energy Audits Commercial Gas Conversion Rebates Ceiling Insulation Grants Solar Water Heater Rebates Solar PV Net Metering Demand Response (PeakSmart) Page 9

The City has a goal to improve the efficiency of customers' end-use of energy resources when such improvements provide a measurable economic and/or environmental benefit to the customers and the City utilities. During the City s last Integrated Resource Planning (IRP) Study completed in 2006 potential DSM measures (conservation, energy efficiency, load management, and demand response) were tested for cost-effectiveness utilizing an integrated approach that is based on projections of total achievable load and energy reductions and their associated annual costs developed specifically for the City. The measures were combined into bundles affecting similar end uses and /or having similar costs per kwh saved. In 2012 the City contracted with a consultant to review its efforts with DSM and renewable resources with a focus on adjusting resource costs for which additional investment and overall market changes impacted the estimates used in the IRP Study. DSM and renewable resource alternatives were evaluated on a levelized cost basis and prioritized on geographic and demographic suitability, demand savings potential and cost. From this prioritized list the consultant identified a combination of DSM and renewable resources that could be costeffectively placed into service by 2016. The total demand savings potential for the resources identified compared well with that identified in the IRP Study providing some assurance that the City s ongoing DSM and renewable efforts remained cost-effective. An energy services provider (ESP) had been under contract since 2010 to assist staff in deploying a portion of the City s DSM program. Staff had worked with the ESP and consultants to develop operational and pricing parameters, craft rate tariffs and solicit participants for a commercial demand response/direct load control (DR/DLC) program. This measure is currently at about 30% of targeted enrollment and the system is online. Although the ESP contract expired in 2015, the City is exploring options to expand its DR/DLC offerings to include deployment of a residential DR/DLC measure which had been delayed while the technology matured. Otherwise, work continues with the City s Neighborhood REACH measure, and participation in the City s other existing DSM measures continues to be steady. As discussed in Section 2.1.1 the growth in customers and energy use has slowed in recent years due in part to the economic conditions observed during and following the 2008-2009 recession as well as due to changes in the federal appliance/equipment efficiency standards and state building efficiency code. It appears that many customers have taken steps on their own to reduce their energy use and costs in response to the changing economy - without taking advantage of the incentives provided through the City s DSM program as well as in response to Page 10

the aforementioned standards and code changes. These free drivers effectively reduce potential participation in the DSM program in the future. And it is questionable whether these customers energy use reductions will persist beyond the economic recovery. History has shown that post-recession energy use generally rebounds to pre-recession levels. In the meantime, however, demand and energy reductions achieved as a result of these voluntary customer actions as well as those achieved by customer participation in City-sponsored DSM measures appear to have had a considerable impact on forecasts of future demand and energy requirements. Estimates of the actual demand and energy savings realized from 2007-2015 attributable to the City s DSM efforts are below those projected in the last IRP study. Due to reduced load and energy forecasts and based on the City s experience to date DSM program participation and thus associated demand and energy savings are not expected to increase as rapidly as originally projected. The latest projections reflect a notable reduction in DSM savings when compared to prior years based in part on historical experience and a true-up of DR/DLC potential in both the City s commercial and residential sectors. Future activities include deployment of residential DR/DLC, expansion of commercial DR/DLC to small and medium-sized businesses and implementation of new commercial demand reduction measures such as thermal energy storage that seek to shift load to the off-peak periods. Staff will continue to periodically review and, where appropriate, update technical and economic assumptions, expected demand and energy savings and re-evaluate the costeffectiveness of current and prospective DSM measures. The City will provide further updates regarding its progress with and any changes in future expectations of its DSM program in subsequent TYSP reports. Energy and demand reductions attributable to the DSM portfolio have been incorporated into the future load and energy forecasts. Tables 2.16 and 2.17 display, respectively, the cumulative potential impacts of the proposed DSM portfolio on system annual energy and seasonal peak demand requirements. Based on the anticipated limits on annual control events it is expected that DR/DLC will be predominantly utilized in the summer months. Therefore, Tables 2.7-2.9 and 2.17 reflect no expected utilization of DR/DLC capability to reduce winter peak demand. Page 11

2.2 ENERGY SOURCES AND FUEL REQUIREMENTS Tables 2.18 (Schedule 5), 2.19 (Schedule 6.1), and 2.20 (Schedule 6.2) present the projections of fuel requirements, energy sources by resource/fuel type in gigawatt-hours, and energy sources by resource/fuel type in percent, respectively, for the period 2016-2025. Figure B4 displays the percentage of energy by fuel type in 2016 and 2025. The City s generation portfolio includes combustion turbine/combined cycle, combustion turbine/simple cycle, conventional steam and hydroelectric units. The City s combustion turbine/combined cycle and combustion turbine/simple cycle units are capable of generating energy using natural gas or distillate fuel oil. This mix of generation types coupled with opportunities for firm and economy purchases from neighboring systems provides allows the City to satisfy its total energy requirements consistent with our energy policies that seek to balance the cost of power with the environmental quality of our community. The projections of fuel requirements and energy sources are taken from the results of computer simulations using the PROSYM production simulation model (provided by Ventyx) and are based on the resource plan described in Chapter III. Page 12

Table 2.1 City Of Tallahassee Schedule 2.1 History and Forecast of Energy Consumption and Number of Customers by Customer Class Base Load Forecast (1) (2) (3) (4) (5) (6) (7) (8) (9) Rural & Residential Commercial [3] Members Average Average kwh Average Average kwh Population Per (GWh) No. of Consumption (GWh) No. of Consumption Year [1] Household [2] Customers Per Customer [2] Customers Per Customer 2006 272,648-1,097 92,017 11,922 1,602 18,533 86,440 2007 273,684-1,099 93,569 11,745 1,657 18,583 89,168 2008 274,926-1,054 94,640 11,137 1,625 18,597 87,380 2009 275,059-1,050 94,827 11,073 1,611 18,478 87,185 2010 275,783-1,136 95,268 11,924 1,618 18,426 87,811 2011 276,799-1,113 95,794 11,619 1,598 18,418 86,763 2012 277,935-1,021 96,479 10,583 1,572 18,445 85,226 2013 279,468-1,014 97,145 10,438 1,544 18,558 83,199 2014 282,471-1,089 97,985 11,119 1,548 18,723 82,690 2015 285,383-1,088 99,007 10,989 1,567 18,820 83,263 2016 287,922-1,108 99,918 11,093 1,591 18,983 83,813 2017 290,743-1,114 100,968 11,031 1,611 19,150 84,133 2018 293,590-1,119 102,028 10,971 1,639 19,318 84,869 2019 296,461-1,125 103,096 10,912 1,656 19,488 84,978 2020 299,224-1,130 104,124 10,855 1,669 19,651 84,937 2021 301,782-1,135 105,076 10,799 1,683 19,802 84,983 2022 304,360-1,139 106,036 10,745 1,693 19,955 84,846 2023 306,961-1,144 107,004 10,691 1,703 20,108 84,710 2024 309,588-1,149 107,981 10,639 1,714 20,264 84,576 2025 312,164-1,153 108,940 10,588 1,724 20,416 84,447 [1] Population data represents Leon County population. [2] Values include DSM Impacts. [3] As of 2007 "Commercial" includes General Service Non-Demand, General Service Demand, General Service Large Demand, Interruptible (FSU and Goose Pond), Curtailable (TMH), Traffic Control, Security Lights and Street & Highway Lights. Page 13

Table 2.2 City Of Tallahassee Schedule 2.2 History and Forecast of Energy Consumption and Number of Customers by Customer Class Base Load Forecast (1) (2) (3) (4) (5) (6) (7) (8) Industrial Street & Total Sales Average Highway Other Sales to Ultimate No. of Average kwh Railroads Lighting to Public Consumers Customers Consumption and Railways (GWh) Authorities (GWh) Year (GWh) [1] Per Customer (GWh) [2] (GWh) [3] 2006 - - - 15 2,714 2007 - - - 0 2,756 2008 - - - 0 2,679 2009 - - - 0 2,661 2010 - - - 0 2,754 2011 - - - 0 2,711 2012 - - - 0 2,593 2013 - - - 0 2,558 2014 - - - 0 2,638 2015 - - - 0 2,655 2016 - - - 0 2,699 2017 - - - 0 2,725 2018 - - - 0 2,759 2019 - - - 0 2,781 2020 - - - 0 2,799 2021 - - - 0 2,818 2022 - - - 0 2,832 2023 - - - 0 2,847 2024 - - - 0 2,863 2025 - - - 0 2,878 [1] Average end-of-month customers for the calendar year. [2] As of 2007 Security Lights and Street & Highway Lighting use is included with Commercial on Schedule 2.1. [3] Values include DSM Impacts. Page 14

Table 2.3 City Of Tallahassee Schedule 2.3 History and Forecast of Energy Consumption and Number of Customers by Customer Class Base Load Forecast (1) (2) (3) (4) (5) (6) Net Energy Total Sales for Utility Use for Load Other No. of Resale & Losses (GWh) Customers Customers Year (GWh) (GWh) [1] (Average No.) [2] 2006 0 154 2,868 0 110,550 2007 0 158 2,914 0 112,152 2008 0 155 2,834 0 113,237 2009 0 140 2,801 0 113,305 2010 0 177 2,931 0 113,694 2011 0 88 2,799 0 114,212 2012 0 117 2,710 0 114,924 2013 0 126 2,684 0 115,703 2014 0 114 2,751 0 116,708 2015 0 121 2,776 0 117,827 2016 0 148 2,847 0 118,901 2017 0 149 2,874 0 120,118 2018 0 152 2,910 0 121,346 2019 0 153 2,934 0 122,584 2020 0 154 2,953 0 123,775 2021 0 154 2,972 0 124,878 2022 0 156 2,988 0 125,990 2023 0 157 3,004 0 127,112 2024 0 157 3,020 0 128,245 2025 0 158 3,035 0 129,356 [1] Values include DSM Impacts. [2] Average number of customers for the calendar year. Page 15

History and Forecast Energy Consumption By Customer Class (Including DSM Impacts) Gigawatt-Hours (GWh) 3,200 2,800 2,400 2,000 1,600 1,200 800 400 Calendar Year Residential Non-Demand Demand Large Demand Curtail/Interrupt Traffic/Street/Security Lights 0 Figure B1 Page 16

Figure B2 Energy Consumption By Customer Class (Excluding DSM Impacts) 1,116 GWh or 41.2% Calendar Year 2016 31 GWh or 1.2% 95 GWh or 3.5% 194 GWh or 7.2% 607 GWh or 22.4% 663 GWh or 24.5% Total 2016 Sales = 2,707 GWh 1,228 GWh or 41.4% Calendar Year 2025 34 GWh or 1.1% 211 GWh or 7.1% 120 GWh or 4% 672 GWh or 22.7% 700 GWh or 23.6% Total 2025 Sales = 2,965 GWh Residential Non-Demand Demand Large Demand Curtail/Interrupt Traffic/Street/Security Lights Page 17

Table 2.4 City Of Tallahassee Schedule 3.1.1 History and Forecast of Summer Peak Demand Base Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2] [2], [3] [2] [2], [3] [1] 2006 577 577 577 2007 621 621 621 2008 587 587 587 2009 605 605 605 2010 601 601 601 2011 590 590 590 2012 557 557 557 2013 543 543 543 2014 565 565 565 2015 601 601 0 1 0 0 600 2016 601 601 0 2 0 1 598 2017 609 609 1 3 4 2 599 2018 618 618 3 5 6 3 601 2019 625 625 5 6 8 5 601 2020 631 631 10 8 10 6 597 2021 637 637 15 9 10 8 595 2022 642 642 20 10 10 9 593 2023 647 647 20 12 10 10 595 2024 652 652 20 13 10 11 598 2025 658 658 20 14 10 13 601 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015 DSM is actual at peak. [3] 2015 values reflect incremental increase from 2014. Page 18

Table 2.5 City Of Tallahassee Schedule 3.1.2 History and Forecast of Summer Peak Demand High Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2] [2], [3] [2] [2], [3] [1] 2006 577 577 577 2007 621 621 621 2008 587 587 587 2009 605 605 605 2010 601 601 601 2011 590 590 590 2012 557 557 557 2013 543 543 543 2014 565 565 565 2015 601 601 0 1 0 0 600 2016 614 614 0 2 0 1 612 2017 625 625 1 3 4 2 616 2018 638 638 3 5 6 3 623 2019 649 649 5 6 8 5 626 2020 659 659 10 8 10 6 625 2021 668 668 15 9 10 8 627 2022 677 677 20 10 10 9 629 2023 686 686 20 12 10 10 635 2024 695 695 20 13 10 11 642 2025 705 705 20 14 10 13 648 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015 DSM is actual at peak. [3] 2015 values reflect incremental increase from 2014. Page 19

Table 2.6 City Of Tallahassee Schedule 3.1.3 History and Forecast of Summer Peak Demand Low Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2] [2], [3] [2] [2], [3] [1] 2006 577 577 577 2007 621 621 621 2008 587 587 587 2009 605 605 605 2010 601 601 601 2011 590 590 590 2012 557 557 557 2013 543 543 543 2014 565 565 565 2015 601 601 0 1 0 0 600 2016 586 586 0 2 0 1 584 2017 590 590 1 3 4 2 581 2018 596 596 3 5 6 3 580 2019 600 600 5 6 8 5 576 2020 602 602 10 8 10 6 569 2021 605 605 15 9 10 8 563 2022 606 606 20 10 10 9 557 2023 608 608 20 12 10 10 557 2024 610 610 20 13 10 11 556 2025 611 611 20 14 10 13 555 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015 DSM is actual at peak. [3] 2015 values reflect incremental increase from 2014. Page 20

Table 2.7 City Of Tallahassee Schedule 3.2.1 History and Forecast of Winter Peak Demand Base Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2], [3] [2], [4] [2], [3] [2], [4] [1] 2006-2007 528 528 528 2007-2008 526 526 526 2008-2009 579 579 579 2009-2010 633 633 633 2010-2011 584 584 584 2011-2012 516 516 516 2012-2013 480 480 480 2013-2014 574 574 574 2014-2015 556 556 556 2015-2016 512 512 0 1 0 0 511 2016-2017 554 554 0 4 0 1 549 2017-2018 562 562 0 5 0 2 555 2018-2019 568 568 0 7 0 2 559 2019-2020 574 574 0 9 0 3 562 2020-2021 580 580 0 11 0 4 565 2021-2022 583 583 0 12 0 4 567 2022-2023 589 589 0 14 0 5 570 2023-2024 593 593 0 15 0 5 573 2024-2025 599 599 0 17 0 6 576 2025-2026 603 603 0 18 0 6 579 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015-2016 DSM is actual at peak. [3] Reflects no expected utilization of demand response (DR) resources in winter. [4] 2015-2016 values reflect incremental increase from 2014-2015. Page 21

Table 2.8 City Of Tallahassee Schedule 3.2.2 History and Forecast of Winter Peak Demand High Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2], [3] [2], [4] [2], [3] [2], [4] [1] 2006-2007 528 528 528 2007-2008 526 526 526 2008-2009 579 579 579 2009-2010 633 633 633 2010-2011 584 584 584 2011-2012 516 516 516 2012-2013 480 480 480 2013-2014 574 574 574 2014-2015 556 556 556 2015-2016 512 512 0 1 0 0 511 2016-2017 569 569 0 4 0 1 565 2017-2018 581 581 0 5 0 2 574 2018-2019 590 590 0 7 0 2 581 2019-2020 599 599 0 9 0 3 588 2020-2021 608 608 0 11 0 4 594 2021-2022 616 616 0 12 0 4 600 2022-2023 625 625 0 14 0 5 606 2023-2024 633 633 0 15 0 5 613 2024-2025 641 641 0 17 0 6 619 2025-2026 650 650 0 18 0 6 625 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015-2016 DSM is actual at peak. [3] Reflects no expected utilization of demand response (DR) resources in winter. [4] 2015-2016 values reflect incremental increase from 2014-2015. Page 22

Table 2.9 City Of Tallahassee Schedule 3.2.3 History and Forecast of Winter Peak Demand Low Forecast (MW) (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Residential Comm./Ind Load Residential Load Comm./Ind Net Firm Management Conservation Management Conservation Demand Year Total Wholesale Retail Interruptible [2], [3] [2], [4] [2], [3] [2], [4] [1] 2006-2007 528 528 528 2007-2008 526 526 526 2008-2009 579 579 579 2009-2010 633 633 633 2010-2011 584 584 584 2011-2012 516 516 516 2012-2013 480 480 480 2013-2014 574 574 574 2014-2015 556 556 556 2015-2016 512 512 0 1 0 0 511 2016-2017 537 537 0 4 0 1 533 2017-2018 542 542 0 5 0 2 536 2018-2019 546 546 0 7 0 2 536 2019-2020 548 548 0 9 0 3 536 2020-2021 550 550 0 11 0 4 536 2021-2022 552 552 0 12 0 4 535 2022-2023 553 553 0 14 0 5 535 2023-2024 555 555 0 15 0 5 535 2024-2025 556 556 0 17 0 6 534 2025-2026 557 557 0 18 0 6 533 [1] Values include DSM Impacts. [2] Reduction estimated at busbar. 2015-2016 DSM is actual at peak. [3] Reflects no expected utilization of demand response (DR) resources in winter. [4] 2015-2016 values reflect incremental increase from 2014-2015. Page 23

Table 2.10 City Of Tallahassee Schedule 3.3.1 History and Forecast of Annual Net Energy for Load Base Forecast (GWh) (1) (2) (3) (4) (5) (6) (7) (8) (9) Residential Comm./Ind Retail Net Energy Load Total Conservation Conservation Sales Utility Use for Load Factor % Year Sales [2], [3] [2], [3] [1] Wholesale & Losses [1] [1] 2006 2,714 2,714 154 2,868 57 2007 2,756 2,756 158 2,914 54 2008 2,679 2,679 155 2,834 55 2009 2,661 2,661 140 2,801 53 2010 2,754 2,754 177 2,931 53 2011 2,711 2,711 88 2,799 54 2012 2,593 2,593 117 2,710 56 2013 2,558 2,558 126 2,684 56 2014 2,638 2,638 114 2,751 55 2015 2,661 6 0 2,655 121 2,776 53 2016 2,707 8 0 2,699 148 2,847 54 2017 2,741 15 1 2,725 149 2,874 55 2018 2,784 23 2 2,759 152 2,910 55 2019 2,815 30 4 2,781 153 2,934 56 2020 2,842 38 5 2,799 154 2,953 56 2021 2,869 45 7 2,818 154 2,972 57 2022 2,893 53 8 2,832 156 2,988 58 2023 2,917 60 10 2,847 157 3,004 58 2024 2,941 68 11 2,863 157 3,020 58 2025 2,965 75 13 2,878 158 3,035 58 [1] Values include DSM Impacts. [2] Reduction estimated at customer meter. 2015 DSM is actual. [3] 2015 values reflect incremental increase from 2014. Page 24

Table 2.11 City Of Tallahassee Schedule 3.3.2 History and Forecast of Annual Net Energy for Load High Forecast (GWh) (1) (2) (3) (4) (5) (6) (7) (8) (9) Residential Comm./Ind Retail Net Energy Load Total Conservation Conservation Sales Utility Use for Load Factor % Year Sales [2], [3] [2], [3] [1] Wholesale & Loss's [1] [1] 2006 2,714 2,714 154 2,868 57 2007 2,756 2,756 158 2,914 54 2008 2,679 2,679 155 2,834 55 2009 2,661 2,661 140 2,801 53 2010 2,754 2,754 177 2,931 53 2011 2,711 2,711 88 2,799 54 2012 2,593 2,593 117 2,710 56 2013 2,558 2,558 126 2,684 56 2014 2,638 2,638 114 2,751 55 2015 2,661 6 0 2,655 121 2,776 53 2016 2,770 8 0 2,762 152 2,914 54 2017 2,821 15 1 2,805 154 2,959 55 2018 2,879 23 2 2,855 157 3,011 55 2019 2,926 30 4 2,893 159 3,051 56 2020 2,971 38 5 2,928 161 3,089 56 2021 3,014 45 7 2,962 162 3,125 57 2022 3,055 53 8 2,994 164 3,159 57 2023 3,095 60 10 3,025 166 3,191 57 2024 3,137 68 11 3,058 168 3,226 57 2025 3,179 75 13 3,091 170 3,261 57 [1] Values include DSM Impacts. [2] Reduction estimated at customer meter. 2015 DSM is actual. [3] 2015 values reflect incremental increase from 2014. Page 25

Table 2.12 City Of Tallahassee Schedule 3.3.3 History and Forecast of Annual Net Energy for Load Low Forecast (GWh) (1) (2) (3) (4) (5) (6) (7) (8) (9) Residential Comm./Ind Retail Net Energy Load Total Conservation Conservation Sales Utility Use for Load Factor % Year Sales [2], [3] [2], [3] [1] Wholesale & Losses [1] [1] 2006 2,714 2,714 154 2,868 57 2007 2,756 2,756 158 2,914 54 2008 2,679 2,679 155 2,834 55 2009 2,661 2,661 140 2,801 53 2010 2,754 2,754 177 2,931 53 2011 2,711 2,711 88 2,799 54 2012 2,593 2,593 117 2,710 56 2013 2,558 2,558 126 2,684 56 2014 2,638 2,638 114 2,751 55 2015 2,661 6 0 2,655 121 2,776 53 2016 2,645 8 0 2,637 145 2,781 54 2017 2,661 15 1 2,645 145 2,790 55 2018 2,689 23 2 2,664 146 2,810 55 2019 2,704 30 4 2,671 146 2,817 56 2020 2,715 38 5 2,673 147 2,819 57 2021 2,727 45 7 2,675 147 2,822 57 2022 2,734 53 8 2,673 147 2,820 58 2023 2,742 60 10 2,672 147 2,819 58 2024 2,750 68 11 2,671 147 2,817 58 2025 2,756 75 13 2,668 146 2,814 58 [1] Values include DSM Impacts. [2] Reduction estimated at customer meter. 2015 DSM is actual. [3] 2015 values reflect incremental increase from 2014. Page 26

Table 2.13 City Of Tallahassee Schedule 4 Previous Year and 2-Year Forecast of Retail Peak Demand and Net Energy for Load by Month (1) (2) (3) (4) (5) (6) (7) 2015 2016 2017 Actual Forecast [1][2] Forecast [1] Peak Demand NEL Peak Demand NEL Peak Demand NEL Month (MW) (GWh) (MW) (GWh) (MW) (GWh) January 556 225 544 235 549 237 February 548 212 524 208 529 210 March 367 201 432 208 436 210 April 447 211 457 210 461 212 May 503 240 524 241 529 244 June 569 262 590 271 595 274 July 600 287 598 284 599 286 August 569 282 592 290 597 293 September 527 244 558 260 564 262 October 452 215 493 224 498 226 November 441 198 418 201 422 203 December 362 198 458 215 462 217 TOTAL 2,776 2,847 2,874 [1] Peak Demand and NEL include DSM Impacts. [2] Represents forecast values for 2016. Page 27

Table 2.14 City of Tallahassee, Florida 2016 Electric System Load Forecast Key Explanatory Variables Tallahassee Minimum Prior Maximum Prior Leon Cooling Heating Per Capita Winter Winter Summer Summer Ln. County Residential Degree Degree Taxable Price of Peak day Peak day Peak day Peak day Appliance No. Model Name Population Customers Days Days Sales Electricity Temp. HDD Temp. Temp. Saturation R Squared [1] 1 Residential Customers X 0.998 2 Residential Consumption X X X X X X 0.936 3 General Service Non-Demand Customers X 0.965 4 General Service Demand Customers X 0.959 5 General Service Non-Demand Consumption X X X X 0.926 6 General Service Demand Consumption X X X 0.956 7 General Service Large Demand Consumption X X X 0.862 8 Summer Peak Demand X X X 0.901 9 Winter Peak Demand X X X 0.918 [1] R Squared, sometimes called the coefficient of determination, is a commonly used measure of goodness of fit of a linear model. If the observations fall on the model regression line, R Squared is 1. If there is no linear relationship between the dependent and independent variable, R Squared is 0. A reasonably good R Squared value could be anywhere from 0.6 to 1. Page 28

Table 2.15 City of Tallahassee 2016 Electric System Load Forecast Sources of Forecast Model Input Information Energy Model Input Data Source 1. Leon County Population Bureau of Economic and Business Research 2. Cooling Degree Days NOAA reports 3. Heating Degree Days NOAA reports 4. AC Saturation Rate Appliance Saturation Study 5. Heating Saturation Rate Appliance Saturation Study 6. Real Tallahassee Taxable Sales Florida Department of Revenue, CPI 7. Florida Population Bureau of Economic and Business Research 8. State Capitol Incremental Department of Management Services 9. FSU Incremental Additions FSU Planning Department 10. FAMU Incremental Additions FAMU Planning Department 11. GSLD Incremental Additions City Utility Services 12. Other Commercial Customers City Utility Services 13. Tall. Memorial Curtailable System Planning/ Utilities Accounting. 14. System Peak Historical Data City System Planning 15. Historical Customer Projections by Class System Planning & Customer Accounting 16. Historical Customer Class Energy System Planning & Customer Accounting 17. GDP Forecast Blue Chip Economic Indicators 18. CPI Forecast Blue Chip Economic Indicators 19. Interruptible, Traffic Light Sales, & System Planning & Customer Accounting Security Light Additions 20. Historical Residential Real Price of Electricity Calculated from Revenues, kwh sold, CPI 21. Historical Commercial Real Price Of Electricity Calculated from Revenues, kwh sold, CPI Page 29

Figure B3 950 900 850 800 750 700 650 600 550 500 Banded Summer Peak Load Forecast Vs. Supply Resources (Load Includes 17% Reserve Margin) Megawatts (MW) 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Calendar Year Supply Base w/ DSM High w/ DSM Low w/ DSM Base w/o DSM Page 30

Table 2.16 City Of Tallahassee 2016 Electric System Load Forecast Projected Demand Side Management Energy Reductions [1] Calendar Year Basis Residential Commercial Total Impact Impact Impact Year (MWh) (MWh) (MWh) 2016 7,911 264 8,175 2017 15,823 791 16,614 2018 23,734 2,373 26,108 2019 31,646 3,956 35,601 2020 39,557 5,538 45,095 2021 47,468 7,120 54,589 2022 55,380 8,703 64,082 2023 63,291 10,285 73,576 2024 71,203 11,867 83,070 2025 79,114 13,449 92,563 [1] Reductions estimated at generator busbar. Page 31

Table 2.17 City Of Tallahassee 2016 Electric System Load Forecast Projected Demand Side Management Seasonal Demand Reductions [1] Residential Commercial Residential Commercial Demand Side Energy Efficiency Energy Efficiency Demand Response Demand Response Management Impact Impact Impact Impact Total Year Summer Winter Summer Winter Summer Winter [2] Summer Winter [2] Summer Winter Summer Winter (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 2016 2016-2017 2 4 1 1 0 0 0 0 2 4 2017 2017-2018 3 5 2 2 1 0 4 0 9 7 2018 2018-2019 5 7 3 2 3 0 6 0 16 9 2019 2019-2020 6 9 5 3 5 0 8 0 23 12 2020 2020-2021 8 11 6 4 10 0 10 0 33 14 2021 2021-2022 9 12 8 4 15 0 10 0 41 16 2022 2022-2023 10 14 9 5 20 0 10 0 49 18 2023 2023-2024 12 15 10 5 20 0 10 0 51 20 2024 2024-2025 13 17 11 6 20 0 10 0 54 22 2025 2025-2026 14 18 13 6 20 0 10 0 56 24 [1] Reductions estimated at busbar. [2] Represents projected winter peak reduction capability associated with demand response (DR) resource. However, as reflected on Schedules 3.1.1-3.2.3 (Tables 2.4-2.9), DR utilization expected to be predominantly in the summer months. Page 32

Table 2.18 City Of Tallahassee Schedule 5 Fuel Requirements (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) Actual Actual Fuel Requirements Units 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 (1) Nuclear Billion Btu 0 0 0 0 0 0 0 0 0 0 0 0 (2) Coal 1000 Ton 0 0 0 0 0 0 0 0 0 0 0 0 (3) Residual Total 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (4) Steam 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (5) CC 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (6) CT 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (7) Diesel 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (8) Distillate Total 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (9) Steam 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (10) CC 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (11) CT 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (12) Diesel 1000 BBL 0 0 0 0 0 0 0 0 0 0 0 0 (13) Natural Gas Total 1000 MCF 22,250 21,649 21,802 21,817 22,205 22,359 22,519 22,315 22,246 22,352 22,556 22,594 (14) Steam 1000 MCF 1,829 1,921 1,055 1,142 1,577 1,377 1,596 0 0 0 0 0 (15) CC 1000 MCF 19,669 18,386 19,888 20,022 19,595 20,290 19,903 19,265 20,673 20,732 19,910 20,823 (16) CT 1000 MCF 752 1,342 859 654 1,033 692 1,020 3,051 1,573 1,621 2,646 1,771 (17) Diesel 1000 MCF 0 0 0 0 0 0 0 0 0 0 0 0 (18) Other (Specify) Trillion Btu 0 0 0 0 0 0 0 0 0 0 0 0 Page 33

Table 2.19 City Of Tallahassee Schedule 6.1 Energy Sources (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) Actual Actual Energy Sources Units 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 (1) Annual Firm Interchange GWh 0 0 18 13 9 4 0 0 0 0 1 0 (2) Coal GWh 0 0 0 0 0 0 0 0 0 0 0 0 (3) Nuclear GWh 0 0 0 0 0 0 0 0 0 0 0 0 (4) Residual Total GWh 0 0 0 0 0 0 0 0 0 0 0 0 (5) Steam GWh 0 0 0 0 0 0 0 0 0 0 0 0 (6) CC GWh 0 0 0 0 0 0 0 0 0 0 0 0 (7) CT GWh 0 0 0 0 0 0 0 0 0 0 0 0 (8) Diesel GWh 0 0 0 0 0 0 0 0 0 0 0 0 (9) Distillate Total GWh 0 0 0 0 0 0 0 0 0 0 0 0 (10) Steam GWh 0 0 0 0 0 0 0 0 0 0 0 0 (11) CC GWh 0 0 0 0 0 0 0 0 0 0 0 0 (12) CT GWh 0 0 0 0 0 0 0 0 0 0 0 0 (13) Diesel GWh 0 0 0 0 0 0 0 0 0 0 0 0 (14) Natural Gas Total GWh 2,788 2,704 2,851 2,854 2,877 2,909 2,925 2,936 2,956 2,971 2,983 3,001 (15) Steam GWh 150 155 89 97 138 120 140 0 0 0 0 0 (16) CC GWh 2,566 2,414 2,678 2,690 2,631 2,717 2,678 2,607 2,789 2,799 2,698 2,813 (17) CT GWh 72 135 84 67 108 72 107 329 167 172 284 188 (18) Diesel GWh 0 0 0 0 0 0 0 0 0 0 0 0 (19) Hydro GWh 20 16 14 14 14 14 14 14 14 14 14 14 (20) Economy Interchange[1] GWh -56 55-35 -38-31 -35-27 -19-22 -21-18 -20 (21) Renewables GWh 0 0 0 32 41 41 40 40 40 40 40 39 (22) Net Energy for Load GWh 2,753 2,776 2,847 2,874 2,910 2,934 2,953 2,972 2,988 3,004 3,020 3,035 [1] Negative values reflect expected need to sell off-peak power to satisfy generator minimum load requirements, primarily in winter and shoulder months. Page 34

Table 2.20 City Of Tallahassee Schedule 6.2 Energy Sources (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) Actual Actual Energy Sources Units 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 (1) Annual Firm Interchange % 0.0 0.0 0.6 0.5 0.3 0.1 0.0 0.0 0.0 0.0 0.0 0.0 (2) Coal % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (3) Nuclear % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (4) Residual Total % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (5) Steam % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (6) CC % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (7) CT % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (8) Diesel % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (9) Distillate Total % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (10) Steam % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (11) CC % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (12) CT % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (13) Diesel % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (14) Natural Gas Total % 101.3 97.4 100.1 99.3 98.9 99.2 99.0 98.8 98.9 98.9 98.8 98.9 (15) Steam % 5.4 5.6 3.1 3.4 4.8 4.1 4.7 0.0 0.0 0.0 0.0 0.0 (16) CC % 93.2 87.0 94.0 93.6 90.4 92.6 90.7 87.7 93.3 93.2 89.4 92.7 (17) CT % 2.6 4.9 3.0 2.3 3.7 2.5 3.6 11.1 5.6 5.7 9.4 6.2 (18) Diesel % 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (19) Hydro % 0.7 0.6 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 (20) Economy Interchange % -2.0 2.0-1.2-1.3-1.1-1.2-0.9-0.6-0.7-0.7-0.6-0.7 (21) Renewables % 0.0 0.0 0.0 1.1 1.4 1.4 1.4 1.4 1.3 1.3 1.3 1.3 (22) Net Energy for Load % 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 Page 35

Figure B4 Generation By Resource/Fuel Type Calendar Year 2016 14 GWh or 0.5% -18 GWh or -0.6% 84 GWh or 3.0% 89 GWh or 3.1% 2,678 GWh or 94.0% Total 2016 NEL = 2,847 GWh Calendar Year 2025 14 GWh or 0.5% 39 GWh or 1.3% -20 GWh or -0.7% 188 GWh or 6.2% 2,813 GWh or 92.7% Total 2025 NEL = 3,035 GWh CC - Gas Steam - Gas CT/Diesel - Gas Net Interchange Hydro Renewables Page 36

Chapter III Projected Facility Requirements 3.1 PLANNING PROCESS In December 2006 the City completed its last comprehensive IRP Study. The purpose of this study was to review future DSM and power supply options that are consistent with the City s policy objectives. Included in the IRP Study was a detailed analysis of how the DSM and power supply alternatives perform under base and alternative assumptions. The preferred resource plan identified in the IRP Study included the repowering of Hopkins Unit 2 to combined cycle operation, renewable energy purchases, a commitment to an aggressive DSM portfolio and the latter year addition of peaking resources to meet future energy demand. Based on more recent information including but not limited to the updated forecast of the City s demand and energy requirements (discussed in Chapter II) the City has made revisions to its resource plan. These revisions will be discussed in this chapter. 3.2 PROJECTED RESOURCE REQUIREMENTS 3.2.1 TRANSMISSION LIMITATIONS The City s projected transmission import capability continues to be a major determinant of the need for future power supply resource additions. The City s internal transmission studies have reflected a gradual deterioration of the system s transmission import (and export) capability into the future, due in part to the lack of investment in the regional transmission system around Tallahassee as well as the impact of unscheduled power flow-through on the City s transmission system. The City has worked with its neighboring utilities, Duke and Southern, to plan and maintain, at minimum, sufficient transmission import capability to allow the City to make emergency power purchases in the event of the most severe single contingency, the loss of the system s largest generating unit. The prospects for significant expansion of the regional transmission system around Tallahassee hinges on the City s ongoing discussions with Duke and Southern, the Florida Reliability Coordinating Council s (FRCC) regional transmission planning process, and the Page 37

evolving set of mandatory reliability standards issued by the North American Electric Reliability Corporation (NERC). Unfortunately, none of these efforts is expected to produce substantive improvements to the City s transmission import/export capability in the short-term. In consideration of the City s limited transmission import capability the results of the IRP Study and other internal analysis of options tend to favor local generation alternatives as the means to satisfy future power supply requirements. To satisfy load, planning reserve and operational requirements in the reporting period, the City may need to advance the in-service date of new power supply resources to complement available transmission import capability. 3.2.2 RESERVE REQUIREMENTS For the purposes of this year s TYSP report the City uses a load reserve margin of 17% as its resource adequacy criterion. This margin was established in the 1990s then re-evaluated via a loss of load probability (LOLP) analysis of the City s system performed in 2002. The City periodically conducts LOLP analyses to determine if conditions warrant a change to its resource adequacy criteria. The results of recent LOLP analyses suggest that reserve margin may no longer be suitable as the City s sole resource adequacy criterion. This issue is discussed further in Section 3.2.4. 3.2.3 RECENT AND NEAR TERM RESOURCE CHANGES At their October 17, 2005 meeting the City Commission gave the Electric Utility approval to proceed with the repowering of Hopkins Unit 2 to combined cycle operation. The repowering was completed and the unit began commercial operation in June 2008. The former Hopkins Unit 2 boiler was retired and replaced with a combustion turbine generator (CTG) and a heat recovery steam generator (HRSG). The Hopkins 2 steam turbine and generator is now powered by the steam generated in the HRSG. Duct burners have been installed in the HRSG to provide additional peak generating capability. The repowering project provides additional capacity as well as increased efficiency versus the unit s capabilities prior to the repowering project. The repowered unit has achieved official seasonal net capacities of 300 MW in the summer and 330 MW in the winter. Page 38

There are several generating unit retirements scheduled in the near term (2016-2020). A total of 56 MW (summer net rating) of generating capacity provided by four (4) small combustion turbines (Hopkins CTs 1 & 2 and Purdom CTs 1 & 2) are planned for retirement by the spring of 2018. Though the retirement dates of these units have been postponed several times in the past the City believes it would not be prudent to consider them as dependable capacity beyond their currently planned retirement dates. In addition, the City s Hopkins Unit 1, which first went into service in 1971, is planned for retirement at the end of 2020. All of these generating units are in excess of 40 years old. Expected future resource additions are discussed in Section 3.2.6, Future Power Supply Resources. 3.2.4 POWER SUPPLY DIVERSITY Resource diversity, particularly with regard to fuels, has long been a priority concern for the City because of the system s heavy reliance on natural gas as its primary fuel source. This issue has received even greater emphasis due to the historical volatility in natural gas prices. The City has addressed this concern in part by implementing an Energy Risk Management (ERM) program to limit the City s exposure to energy price fluctuations. The ERM program established an organizational structure of interdepartmental committees and working groups and included the adoption of an Energy Risk Management Policy. This policy identifies acceptable risk mitigation products to prevent asset value losses, ensure price stability and provide protection against market volatility for fuels and energy to the City s electric and gas utilities and their customers. Other important considerations in the City s planning process are the diversity of power supply resources in terms of their number, sizes and expected duty cycles as well as expected transmission import capabilities. To satisfy expected electric system requirements the City currently assesses the adequacy of its power supply resources versus the 17% load reserve margin criterion. But the evaluation of reserve margin is made only for the annual electric system peak demand and assuming all power supply resources are available. Resource adequacy must also be evaluated during other times of the year to determine if the City is maintaining the appropriate amount and mix of power supply resources. Currently, about two-thirds of the City s power supply comes from two generating units, Purdom 8 and Hopkins 2. The outage of either of these units can present operational challenges Page 39

especially when coupled with transmission limitations (as discussed in Section 3.2.1). Further, the projected retirement of older generating units will reduce the number of power supply resources available to ensure resource adequacy throughout the reporting period. For these reasons the City has evaluated alternative and/or supplemental probabilistic metrics to its current load reserve margin criterion, such as loss of load expectation (LOLE), that may better balance resource adequacy and operational needs with utility and customer costs. The results of this evaluation confirmed that the City s current capacity mix and limited transmission import capability are the biggest determinants of the City s resource adequacy and suggest that there are risks of potential resource shortfalls during periods other than at the time of the system peak demand. Therefore, the City s current deterministic load reserve margin criterion may need to be increased and/or supplemented by a probabilistic criterion that takes these issues into consideration. Purchase contracts can provide some of the diversity desired in the City s power supply resource portfolio. The City s last IRP Study evaluated both short and long-term purchased power options based on conventional sources as well as power offers based on renewable resources. A consultant-assisted study completed in 2008 evaluated the potential reliability and economic benefits of prospectively increasing the City s transmission import (and export) capabilities. The results of this study indicate the potential for some electric reliability improvement resulting from the addition of facilities to achieve more transmission import capability. However, the study s model of the Southern and Florida markets reflects, as with the City s generation fleet, natural gas-fired generation on the margin the majority of the time. Therefore, the cost of increasing the City s transmission import capability would not likely be offset by the potential economic benefit from increased power purchases from conventional sources. As an additional strategy to address the City s lack of power supply diversity, planning staff has investigated options for a significantly enhanced DSM portfolio. Commitment to this expanded DSM effort (see Section 2.1.3) and an increase in customer-sited renewable energy projects (primarily solar panels) improve the City s overall resource diversity. However, due to limited availability and uncertain performance, studies indicate that DSM and solar projects would not improve resource adequacy (as measured by LOLE) as much as the addition of conventional generation resources. Page 40

3.2.5 RENEWABLE RESOURCES The City believes that offering green power alternatives to its customers is a sound business strategy: it will provide for a measure of supply diversification, reduce dependence on fossil fuels, promote cleaner energy sources, and enhance the City s already strong commitment to protecting the environment and the quality of life in Tallahassee. As part of its continuing commitment to explore clean energy alternatives, the City has continued to invest in opportunities to develop viable solar photovoltaic (PV) projects as part of our efforts to offer green power to our customers. The City continues to seek out suitable projects that utilize the renewable fuels available within the big bend and panhandle of Florida. In February 2015, the City issued a request for proposals (RFP) for a purchase power agreement (PPA) for a 10 MWac utility scale solar PV project. During the negotiations of the Purchase Power Agreement, the project developer offered expand the project from 10 MWac to 20 MWac. On February 24, 2016, the City Commission voted to authorize negogiations for a PPA for 20 MWac. It is expected that the project will be located within the City s service territory or adjacent to a City-owned facility. Due to the intermittent nature of solar PV the PPA will be for energy only and will not be considered firm capacity. It is anticipated that this facility will be operational by the summer of 2017. Although there are ongoing concerns regarding the potential impact on service reliability associated with reliance on a significant amount of intermittent resources like PV on the City s relatively small electric system, the City will continue to monitor the proliferation of PV and other intermittent resources and work to integrate them so that service reliability is not jeopardized. As of the end of calendar year 2015 the City has a portfolio of 232 kw of solar PV operated and maintained by the Electric Utility and a cumulative total of 1,502 kw of solar PV has been installed by customers. The City promotes and encourages environmental responsibility in our community through a variety of programs available to citizens. The commitment to renewable energy sources (and particularly to solar PV) by its customers is made possible through the Go Green Tallahassee initiative, that includes many options related to becoming a greener community such as the City s Solar PV Net Metering offer. Solar PV Net Metering promotes customer investment in renewable energy generation by allowing residential Page 41

and commercial customers with small to moderate sized PV installations to return excess generated power back to the City at the full retail value. In 2011, the City of Tallahassee signed contracts with SunnyLand Solar and Solar Developers of America (SDA) for over 3 MWs of solar PV. These demonstration projects are to be built within the City s service area and will utilize new technology pioneered by Florida State University. As of December 31, 2015 both of these projects continue to face delays due to manufacturing and development issues associated with the technology. Such delays are to be expected with projects involving the demonstration of emerging technologies. While the project developers have not announced a revised commercial operations date (COD), the City remains optimistic that the technology will mature into a viable energy resource. Until a new COD is announced, this will be the last reporting of these projects. 3.2.6 FUTURE POWER SUPPLY RESOURCES The City currently projects that additional power supply resources will be needed to maintain electric system adequacy and reliability through the 2025 horizon year. As a result of the lower demand and energy reductions expected from DSM (discussed in Section 2.1.3) the City has determined that additional capacity will be needed by the summer of 2018 in order to satisfy its 17% reserve margin criterion. A generation project is being developed at the City s Substation 12. The project is primarily intended as a solution to a transmission constraint. Standard industry practice is to have to have at least two transmission lines serving each substation to ensure electric service reliability. However, Substation 12 is currently only served via a single transmission line. Substation 12 serves a number of critical loads within the City s service territiory including, but not limited to, Tallahassee Memorial Hospital (TMH), a large number of community medical offices/facilities adjacent to TMH, and the Tallahassee Police Department. Due to the density of businesses, residences and roadways in the area, it is not cost feasible to add another transmission line to this substation. As an alternative, a generation project located at the substation will provide about 18 MW (in the form of natural gas fueled reciprocating internal combustion engines (RICE or IC)) to back up the critical loads from this substation. This Page 42

capacity addition would satisfy the load and reserve requirements from summer 2018 through the summer of 2020. In addition to the generating capacity to be added at Substation 12 new generating capacity will be needed following the planned retirement of the City s Hopkins Unit 1 (76 MW) at the end of 2020. Based on the City s 17% reserve margin criterion an additional 64 MW of generating capacity would be needed by the summer of 2021. City staff has been exploring alternatives for addressing the need to replace Hopkins Unit 1 and has found that there may be opportunities to achieve additional benefits. The option that currently appears most attractive is the installation of 50-100 MW of small (10-20 MW each) RICE generators similar to those planned for Substation 12. The RICE generators could provide additional benefits including but not necessarily limited to: The RICE generators could all be installed at the same time or phased over a period of years. This flexibility would allow the City to add the resources as needed. The RICE generators could be installed at either the City s Hopkins plant or split between the Hopkins plant and Purdom plant. The RICE generators are more efficient than the units that are being retired. As a result, preliminary analyses indicate significant potential fuel savings. The RICE generators can be started and reach full load within 5-10 minutes. In addition, their output level can be changed very rapidly. This makes them excellent for responding to the changes in output from intermittent resources such as solar energy systems and may enable the addition of more solar resources in the future. The CO2 emissions from the RICE generators are much lower than the units scheduled to be retired. Hopkins Unit 1 currently has a minimum up time requirement of 100 hours. This may at times require the unit to remain on line during daily off-peak periods when the unit s generation is not needed and/or may represent excess generation that must be sold, possibly at a loss. Replacing Hopkins Unit 1 with the smaller, quick start RICE generators would allow the City to avoid this uneconomic operating practice. There may be merit to retiring Hopkins Unit 1 earlier and advancing the in-service dates of these RICE generators. Preliminary analyses indicate that some of the associated debt service could be offset by the fuel savings from the efficiency gains achieved by these Page 43

units. There is also a possibility that better pricing could be obtained if the City purchased more RICE generators than just those needed for the Substation 12 project. The timing, site, type and size of any new power supply resource may vary dependent upon the metric(s) used to determine resource adequacy and as the nature of the need becomes better defined. Any proposed addition could be a generator or a peak season purchase. The suitability of this resource plan is dependent on the performance of the City s DSM portfolio (described in Section 2.1.3 of this report) and the City s projected transmission import capability. If only 50% of the projected annual DSM peak demand reductions are achieved, the City would require about 33 MW of additional power supply resources to meet its load and planning reserve requirements through the horizon year of 2025. The City continues to monitor closely the performance of the DSM portfolio and, as mentioned in Section 2.1.3, will be revisiting and, where appropriate, updating assumptions regarding and re-evaluating cost-effectiveness of our current and prospective DSM measures. This will also allow a reassessment of expected demand and energy savings attributable to DSM. Tables 3.1 and 3.2 (Schedules 7.1 and 7.2) provide information on the resources and reserve margins during the next ten years for the City s system. The City has specified its planned capacity changes on Table 3.3 (Schedule 8). These capacity resources have been incorporated into the City s dispatch simulation model in order to provide information related to fuel consumption and energy mix (see Tables 2.18, 2.19 and 2.20). Figure C compares seasonal net peak load and the system reserve margin based on summer peak load requirements. Table 3.4 provides the City s generation expansion plan for the period from 2016 through 2025. Page 44

Figure C MW 800 700 600 500 400 300 200 100 0 System Peak Demands (Including DSM Impacts) Summer 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Year Winter Summer Reserve Margin (RM) Percent Reserve 50 45 40 35 30 25 20 15 10 5 0 RM w/ DSM RM w/o DSM 17% RM Criterion 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Year Page 45

Table 3.1 City Of Tallahassee Schedule 7.1 Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Summer Peak [1] (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) Total Firm Firm Total System Firm Installed Capacity Capacity Capacity Summer Peak Reserve Margin Scheduled Reserve Margin Capacity Import Export QF Available Demand Before Maintenance Maintenance After Maintenance Year (MW) (MW) (MW) (MW) (MW) (MW) (MW) % of Peak (MW) (MW) % of Peak 2016 746 0 0 0 746 598 148 25 0 148 25 2017 734 0 0 0 734 599 135 23 0 135 23 2018 708 0 0 0 708 601 107 18 0 107 18 2019 708 0 0 0 708 601 108 18 0 108 18 2020 708 0 0 0 708 597 111 19 0 111 19 2021 706 0 0 0 706 595 111 19 0 111 19 2022 706 0 0 0 706 593 113 19 0 113 19 2023 706 0 0 0 706 595 111 19 0 111 19 2024 706 0 0 0 706 598 108 18 0 108 18 2025 706 0 0 0 706 601 105 17 0 105 17 [1] All installed and firm import capacity changes are identified in the proposed generation expansion plan (Table 3.4). Page 46

Table 3.2 City Of Tallahassee Schedule 7.2 Forecast of Capacity, Demand, and Scheduled Maintenance at Time of Winter Peak [1] (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) Total Firm Firm Total System Firm Installed Capacity Capacity Capacity Winter Peak Reserve Margin Scheduled Reserve Margin Capacity Import Export QF Available Demand Before Maintenance Maintenance After Maintenance Year (MW) (MW) (MW) (MW) (MW) (MW) (MW) % of Peak (MW) (MW) % of Peak 2016/17 822 0 0 0 822 549 273 50 0 273 50 2017/18 788 0 0 0 788 555 233 42 0 233 42 2018/19 780 0 0 0 780 559 222 40 0 222 40 2019/20 780 0 0 0 780 562 219 39 0 219 39 2020/21 776 0 0 0 776 565 211 37 0 211 37 2021/22 776 0 0 0 776 567 209 37 0 209 37 2022/23 776 0 0 0 776 570 206 36 0 206 36 2023/24 776 0 0 0 776 573 203 35 0 203 35 2024/25 776 0 0 0 776 576 200 35 0 200 35 2025/26 776 0 0 0 776 579 197 34 0 197 34 [1] All installed and firm import capacity changes are identified in the proposed generation expansion plan (Table 3.4). Page 47

Table 3.3 City Of Tallahassee Schedule 8 Planned and Prospective Generating Facility Additions and Changes (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) Const. Commercial Expected Gen. Max. Net Capability Unit Unit Fuel Fuel Transportation Start In-Service Retirement Nameplate Summer Winter Plant Name No. Location Type Pri Alt Pri Alt Mo/Yr Mo/Yr Mo/Yr (kw) (MW) (MW) Status Hopkins CT-1 Leon GT NG DFO PL TK NA 2/70 4/17 16,320-12 -14 RT Purdom CT-1 Wakulla GT NG DFO PL TK NA 12/63 10/17 15,000-10 -10 RT Purdom CT-2 Wakulla GT NG DFO PL TK NA 5/64 10/17 15,000-10 -10 RT Hopkins CT-2 Leon GT NG DFO PL TK NA 9/72 4/18 27,000-24 -26 RT Hopkins 1 Leon ST NG NA PL NA NA 5/71 1/21 75,000-76 -78 RT Sub 12 DG IC 1-2 [1] Leon IC NG NA PL NA 6/16 6/18 NA 9,341 18 18 P Hopkins IC 1-4 [1] Leon IC NG NA PL NA 1/19 1/21 NA 9,341 37 37 P Purdom IC 1-4 [1] Leon IC NG NA PL NA 1/19 1/21 NA 9,341 37 37 P Acronyms GT Gas Turbine Pri Primary Fuel kw Kilowatts ST Steam Turbine Alt Alternate Fuel MW Megawatts IC Internal Combustion NG Natural Gas RT Existing generator scheduled for retirement. DFO Diesel Fuel Oil P Planned for installation but not utility authorized. Not under construction. RFO Residual Fuel Oil PL Pipeline TK Truck [1] For the purposes of this report, the City has identified the addition of up to ten (10) 9.2 MW reciprocating internal combustion engine (RICE) generating units to be located at its existing Substation 12, Hopkins Plant and/or Purdom Plant sites. The number, timing, site, type and size of new power supply resources may vary as the nature of the need becomes better defined. Alternatively, this proposed addition could be a generator(s) of a different type/size at the same or different locations or a peak season purchase. Page 48

Table 3.4 City Of Tallahassee Generation Expansion Plan Load Forecast & Adjustments Forecast Net Existing Resource Peak Peak Capacity Firm Firm Additions Total Demand DSM [1] Demand Net Imports Exports (Cumulative) Capacity Res Year (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) % 2016 601 2 598 746 0 746 25 2017 609 9 599 734 [2,3] 0 734 23 2018 618 16 601 690 [4,6] 0 18 [6] 708 18 2019 625 23 601 690 0 18 708 18 2020 631 33 597 690 0 18 708 19 2021 637 41 595 614 [5] 0 92 [6] 706 19 2022 642 49 593 614 0 92 706 19 2023 647 51 595 614 0 92 706 19 2024 652 54 598 614 0 92 706 18 2025 658 56 601 614 0 92 706 17 Notes [1] Demand Side Management includes energy efficiency and demand response/control measures. [2] Hopkins CT 1 official retirement currently scheduled for April 2017. [3] Purdom CTs 1 and 2 official retirement currently scheduled for October 2017. [4] Hopkins CT 2 official retirement currently scheduled for April 2018. [5] Hopkins ST 1 official retirement currently scheduled for January 2021. [6] For the purposes of this report, the City has identified the addition of up to ten (10) 9.2 MW reciprocating internal combustion engine (RICE) generating units to be located at its existing Substation 12 (2018), Hopkins Plant and/or Purdom Plant (2021) sites. The number, timing, site, type and size of new power supply resources may vary as the nature of the need becomes better defined. Alternatively, this proposed addition could be a generator(s) of a different type/size at the same or different locations or a peak season purchase. Page 49

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Chapter IV Proposed Plant Sites and Transmission Lines 4.1 PROPOSED PLANT SITE As discussed in Chapter 3 the City currently expects that additional power supply resources will be required in the reporting period to meet future system needs (see Table 4.1). For the purposes of this report, the City has identified the addition of up to ten (10) 9 MW natural gas fueled reciprocating internal combustion engines (RICE or IC) at its Substation 12, its existing Hopkins Plant and/or its existing Purdom Plant site. The timing, site, type and size of this new power supply resource may vary as the nature of the need becomes better defined. Alternatively, this proposed addition could be a generator(s) of a different type/size at the same or different location or a peak season purchase. 4.2 TRANSMISSION LINE ADDITIONS/UPGRADES Internal studies of the transmission system have identified a number of system improvements and additions that will be required to reliably serve future load. The majority of these improvements are planned for the City s 115 kv transmission network. As discussed in Section 3.2, the City has been working with its neighboring utilities, Duke and Southern, to identify improvements to assure the continued reliability and commercial viability of the transmission systems in and around Tallahassee. At a minimum, the City attempts to plan for and maintain sufficient transmission import capability to allow for emergency power purchases in the event of the most severe single contingency, the loss of the system s largest generating unit. The City s internal transmission studies have reflected a gradual deterioration of the system s transmission import (and export) capability into the future. This reduction in capability is driven in part by the lack of investment in facilities in the panhandle region as well as the impact of unscheduled power flow-through on the City s transmission system. The City is committed to continue to work with Duke and Southern as well as existing and prospective regulatory bodies in an effort to pursue improvements to the regional transmission systems that will allow the City to continue to provide reliable and affordable Page 51

electric service to the citizens of Tallahassee in the future. The City will provide the FPSC with information regarding any such improvements as it becomes available. Beyond assessing import and export capability, the City also conducts annual studies of its transmission system to identify further improvements and expansions to provide increased reliability and respond more effectively to certain critical contingencies both on the system and in the surrounding grid in the panhandle. These evaluations indicate that additional infrastructure projects are needed to address (i) improvements in capability to deliver power from the Hopkins Plant (on the west side of the City s service territory) to the load center, and (ii) the strengthening of the system on the east side of the City s service territory to improve the voltage profile in that area and enhance response to contingencies. The City s transmission expansion plan includes a 230 kv loop around the City to be completed by Spring 2017 to address these needs and ensure continued reliable service consistent with current and anticipated FERC and NERC requirements. As the first phase of this transmission project, the City tapped its existing Hopkins-Duke Crawfordville 230 kv transmission line and extended a 230 kv transmission line to the east terminating at the existing Substation BP-5. The City next upgraded existing 115 kv line to 230 kv from Substation BP-5 to Substation BP-4 as the second phase of the project. As part of the second phase additional 230/115 kv transformation was placed in service at BP-4. The final phase of the project will be to upgrade the existing 115 kv line from Substation BP-4 to Substation BP-7 to 230 kv thereby completing the loop by Spring 2017. This new 230 kv loop would address a number of potential line overloads for the single contingency loss of other key transmission lines in the City s system. Table 4.2 summarizes the proposed new facilities or improvements from the transmission planning study that are within this reporting period. The City s budget planning cycle for FY 2017 is currently ongoing, and any revisions to project budgets in the electric utility will not be finalized until the summer of 2016. Some of the construction of the aforementioned 230 kv transmission projects is currently underway. If these improvements do not remain on schedule the City has prepared operating solutions to mitigate adverse system conditions that might occur as a result of the delay in the in-service date of these improvements. Page 52

Table 4.1 City Of Tallahassee Schedule 9 Status Report and Specifications of Proposed Generating Facilities (1) Plant Name and Unit Number: Substation 12 IC 1-2 [1] Hopkins IC 1-4 Purdom IC 1-4 (2) Capacity a.) Summer: 9.2 b.) Winter: 9.2 (3) Technology Type: IC (4) Anticipated Construction Timing a.) Field Construction start - date: b.) Commercial in-service date: (5) Fuel a.) Primary fuel: b.) Alternate fuel: Jun-16 Jun-18 NG (6) Air Pollution Control Strategy: BACT compliant (7) Cooling Status: Unknown (8) Total Site Area: Unknown (9) Construction Status: Not started (10) Certification Status: Not started (11) Status with Federal Agencies: Not started (12) Projected Unit Performance Data Planned Outage Factor (POF): 0.86 Forced Outage Factor (FOF): 3.79 Equivalent Availability Factor (EAF): 92.63 Resulting Capacity Factor (%): 1.6 [2] Average Net Operating Heat Rate (ANOHR): 8,580 [3] (13) Projected Unit Financial Data Book Life (Years) 30 Total Installed Cost (In-Service Year $/kw) 1,669 [4] Direct Construction Cost ($/kw): 1,589 [5] AFUDC Amount ($/kw): NA Escalation ($/kw): 80 Fixed O & M ($kw-yr): 31.50 [5] Variable O & M ($/MWH): 9.87 [5] K Factor: NA Notes [1] The generator "Capacity", "Projected Unit Performance Data" and "Projected Unit Financial Data" reflect those for a single unit. For the purposes of this report, the City has identified the addition of up to ten (10) 9.2 MW reciprocating internal combustion engine (RICE) generating units to be located at its existing Substation 12, Hopkins Plant and/or Purdom Plant sites. The number, timing, site, type and size of new power supply resources may vary as the nature of the need becomes better defined. Alternatively, this proposed addition could be a generator(s) of a different type/size at the same or different locations or a peak season purchase. [2] Expected first year capacity factor for prospective Substation 12 additions. [3] Expected first year net average heat rate for prospective Substation 12 additions. [4] Estimated 2018 dollars for prospective Substation 12 additions. [5] Estimated 2016 dollars. Page 53

Figure D-1 Hopkins Plant Site Figure D-2 Purdom Plant Site Page 54